The well drainage pressure and radius are key parameters of real-time well and reservoir performance optimization, well test design and new wells' location identification. Currently, the primary method of estimating the well drainage radius is buildup tests and their subsequent well test analysis. Such buildup tests are conducted using wireline-run quartz gauges for an extended well shut-in period resulting in deferred production and risky operations.
A calculation method for predicting well/reservoir drainage pressure and radius is proposed based on single-downhole pressure gauge, flowing well parameters and PVT data. The proposed method uses a simple approach and applies established well testing equations on the flowing pressure and rates of a well to estimate its drainage parameters. This method of estimation is therefore not only desirable, but also necessary to eliminate shutting-in producing wells for extended periods; in addition to avoiding the cost and risk associated with the wireline operations. The results of this calculation method has been confirmed against measured downhole, shut-in pressure using wireline run gauges as well as dual gauge completed wells in addition to estimated well parameters from buildup tests.
This paper covers the procedure of the real-time estimation of the well/reservoir drainage pressure and radius in addition to an error estimation method between the measured and calculated parameters. Furthermore, the paper shows the value, applicability and validity of this technique through multiple examples.
Osode, Peter Ikechukwu (Saudi Arabian Oil Company) | Otaibi, Msalli A. (Saudi Aramco) | El-Kilany, Khaled Ahmed (Saudi Aramco) | Binmoqbil, Khalid Hamoud (Saudi Aramco) | Azizi, Eddy Sarhan (Saudi Aramco)
Reactive mud cake breaker fluids in long open hole horizontal wells located across high permeability sandstone reservoirs has had limited success because they often induce massive fluid losses. The fluid losses are controlled with special pills,
polymers and brine or water, causing well impairment that is difficult to remove when oil-based mud (OBM) drill-in fluids (DIFs) are used. This situation has resulted in the drive for an alternative cleanup fluid system that is focused on preventing
excessive fluid leak off, maximizing the OBM displacement efficiency and allowing partial dispersion of the mud cake for ease of its removal during initial well production. The two-stage spacer application is composed of a nonreactive fluid
system, which includes a viscous pill with nonionic surfactants, gel pill, completion brine and a solvent.
Extensive laboratory evaluation was conducted at simulated reservoir conditions to evaluate the effectiveness of the OBM displacement fluid system. The study included dynamic high-pressure/high temperature (HP/HT) filter press tests and
coreflood tests in addition to wettability alteration, interfacial tension and fluid compatibility tests.
The spacer fluid parameters were optimized based on wellbore fluid hydraulic simulation and laboratory test results, which indicated minimal fluid leak off and a low risk of emulsion formation damage. Three well trials were conducted in a major
offshore field sandstone reservoir drilled with OBM. All three trial wells (one single and two dual laterals), which were treated, have demonstrated improvement in production performance. This paper will discuss in detail the spacer fluids
optimization process, laboratory work conducted and the successful field treatments performed.
The Intelligent Field in Saudi Aramco is gaining widespread applicability after successful implementation in its oil fields for real-time data acquisition. The historical field data collected on equipment status and project development enables to build a case study on process management strategies to improve the performance of Intelligent Fields surface facilities project execution and deployment.
The application of this study focuses on the analysis of the project commissioning stage of Intelligent Fields surface facilities and how business strategies can increase the efficiency of the process through the involved organizations. Project commissioning requires an integrative process and operational effort across internal organizations: facilities, projects, production and operations, as well as the involvement of external organizations such as equipment manufacturers, contractors and service providers.
The results present an integrative approach on process workflow optimization and performance measurement for project execution as well as gap analysis and root cause analysis for continuous improvement. Here, the asset team involvement is recognized as a central entity that brings together stakeholders to pursue improvement and measure implementation through strategic alignment with business goals.
The case study contribution resides in how to foster efficiency in the project execution of Intelligent Fields surface facilities through performance improvement strategies. Efficiency is driven by cross-organizational teams who mitigate the challenges throughout the commissioning and start-up stages.
Downhole pressure and temperature sensors have been installed either separately as stand-alone sensors hanged on the production tubing of a well or jointly with Electric Submersible Pumps (ESPs) or Intelligent Well Completions (IWC). However, their utilization thus far has been limited to static/flowing bottom-hole pressures measurement for buildup/drawdown pressure tests analysis or ESP/intelligent well performance monitoring.
Eighty-eight (88) wells located offshore Saudi Arabia have been equipped with ESPs combined with downhole pressure and temperature sensors installed at the intake and discharge of the pumps. Each well was equipped with a surface coriolis meter to measure the total liquid flow rate and water-cut assuming that the well's production will be maintained above the bubble point pressure. However, the coriolis meters' readings have become erroneous ever since the wells' flowing wellhead pressure declined to and below the saturation pressure due to the flow of liberated gas through the meters. In order to compensate for the meters' measurement deviation, wellhead samples had to be collected and analyzed to determine the wells water-cuts where the total flow measurement was still acceptable. Alternatively, other means of multiphase flow rate measurements were used. This has proven to be costly and time consuming.
This paper proposes a technique which uses real-time data transmitted from existing surface and subsurface sensors to calculate the water-cut and flow rate of each well and avoid the risky and costly field trips for wellhead sample collection and analysis. In addition, the paper describes an innovative technique to estimate the error in the measured density and calculated water-cut based on the bubble point pressure which accurately determines the application envelope of this method. The paper provides examples to illustrate the validity of the proposed technique in comparison with measured and sampled water-cuts which were collected above and below the bubble point pressure. Furthermore, the paper sheds light on the main issues impacting the method's reliability.